Worldwide, there is an estimated recoverable reserve of more than 950 billion barrels (150.million cubic meters) of what is known as “conventional” liquid hydrocarbon (oil) disposed in subsurface reservoirs. Of the foregoing, about 600 billion barrels (96.million cubic meters), about 66%, are disposed in the geographic region of the Middle East. 85% of conventional liquid hydrocarbon is located in the eastern hemisphere.
The estimated recoverable reserve of so called “heavy oil” is about 430 billion barrels (70.million cubic meters) and there are estimated to be 650 billion barrels (103.million cubic meters) of bitumen (solid hydrocarbon associated with Earth formations). Of the total recoverable reserve of the foregoing two hydrocarbon sources about 70% (equivalent to about 830 billion barrels of oil) are geographically disposed in the Western hemisphere with 81% of such bitumen located within North America and 62% percent of the heavy oil located within South America. The total world oil reserves, including heavy oil, are believed to be about 2 trillion barrels. At a consumption rate of 100 million barrels per day, such total world oil reserves have an estimated life of about 55 years. Thus, the above reserves of heavy oil and bitumen are important to the world hydrocarbon economy, and may be sampled to provide optimal recovery and design production strategies.
According to the United States Geological Survey (USGS) heavy oil may be categorized according to the density and viscosity of the fluid. The definitions, listed in Table 1, were obtained from a web page published by the USGS at the Uniform Resource Locator (URL) http://pubs.usgs.gov/fs/fs070-03/fs070-03.html.
TABLE 1Definition of the type of heavy oil based on the density ρ,API gravity and viscosity η, of the fluid along with commentsconcerning mobility and current extraction methodsAPIDefinitionρ (kg/m3)Gravityη (cP)CommentsMedium heavy oil903 to 94625 to 18100 to 10Mobile fluid atreservoir conditionsExtra heavy oil933 to 102120 to 710,000 to 100Immobile fluid atreservoir conditionsTar sands and985 to 1021<12>10,000Immobile solid atbitumenreservoir conditions
In addition to the USGS, the United Nations Information Centre for Heavy Crude and Tar Sands offers definitions for bitumen as petroleum having a viscosity above about 10,000 cP (centipoise) while petroleum with viscosity below about 10,000 cP is classified as heavy oil. Heavy oil is further classified into heavy oil with an American Petroleum Institute (“API”) gravity between 10 and 20 degrees API gravity and extra heavy oil with a gravity below about 10 degrees API. In the present disclosure, the foregoing definitions may be used for heavy oils, which are typically liquids at subsurface reservoir temperature, and bitumen, that is typically solid (glass like) at subsurface reservoir temperatures.
Samples of formation fluids in subsurface reservoirs may be extracted by inserting instruments referred to as “sampling tools”, or having a similar designation, into a wellbore drilled through the subsurface formations. Such tools extract a sample by selectively exposing the formation to a chamber in the tool having a lower pressure than the fluid pressure in the pore spaces of the formations. There are a number of reasons why hydrocarbon samples should be acquired from subsurface reservoirs for evaluation of such reservoirs. For heavy oil and bitumen, samples may be important because they may be used to evaluate production strategies and select the most energy efficient and environmentally acceptable methods for extracting the hydrocarbons from the subsurface reservoirs. The sampling process may, as is the case for liquid oil, extract samples with a chemical composition and physical properties that are representative of the hydrocarbons as they exist in the reservoir. The time efficiency of sampling increases with increasing fluid flow-rate, Q, that may be determined from Darcy's law:Q∝Δp·k/η  (1)
where Δp is the pressure difference applied by a formation fluid sampling tool to withdraw the fluid from the subsurface reservoir, η the formation fluid viscosity and k the reservoir permeability. Darcy's law may be used to estimate the pressure difference created by the suction device between the pressure at the entrance to the sampling tool and the formation. For a fluid with effective viscosity 300 cP in a rock of permeability about 3.0 Darcies with a flow rate of 1 cm3 s−1 the pressure drop is about 3 MPa (about 435 psi) while for an effective viscosity of 3,000 cP the pressure difference is 33 MPa (about 4,786 psi). For many heavy oils the reservoir pressure is about 10 MPa (equivalent to 1,450 psi). A pressure drop of about 4,700 psi may be difficult to achieve while even that of 435 psi may induce an undesirable phase transition in the fluid being sampled.
According to equation (1), the flow rate Q increases by increasing either the pressure differential Δp or the reservoir permeability k and/or by decreasing the fluid viscosity η. As mentioned before, the magnitude of the pressure differential Δp may be limited by characteristics of the sampling tool (e.g., the sampling tool operation envelope), by existing fluid pressure in the reservoir and by the mechanical properties of the subsurface formation. For example, the value of the pressure differential Δp may be limited by a pressure differential value at which the formation fails. Also, the reservoir permeability k is an intrinsic property of the subsurface formation and, with exceptions such as hydraulic fracturing, may be practically difficult to change. Therefore, practical implementations for sampling low mobility formation fluids may rely on methods of decreasing the fluid viscosity η.
There are many methods that may be used to reduce viscosity and some of those methods may be preferred to avoid chemically altering the fluid as or before it is withdrawn into the sample taking tool. Sampling of low mobility fluids may be performed by either thermal (heating) or non-thermal methods, such as methods which rely on injecting a solvent into the subsurface formation to reduce the fluid viscosity. The thermal methods have an advantage over the non-thermal methods because the sample chemical composition is generally not changed as would be the case by introduction of a solvent.
A heavy oil or bitumen sample may preferably be chemically representative of the heavy oil or bitumen as it exists in the formation, so that, for example, a suitable production strategy may be determined from the sample. The method chosen to extract the sample may therefore involve increasing the mobility of the fluid to be sampled (mobility being related to the ratio of permeability to viscosity) in both the reservoir and within the sample taking tool so that the heavy oil or bitumen may be drawn into a sample retrieval vessel in the tool. The mobility enhancement may be achieved in such a manner that the sample composition either represents the important characteristics of the reservoir (heavy oil or bitumen) fluid sufficiently well or that the physical characteristics of the fluid have been changed in a reversible manner.
The use of electromagnetic radiation to heat heavy oil formations for the purpose of production of hydrocarbon therefrom has been investigated by others. For example, multiple radio frequency (“RF”) sources separated by about 6 m were operated at frequencies between 2.3 and 13.6 MHz and power of up to 75 kW for about 25 days. Such was reported to have heated the formation to a temperature of 200° C. and recovered between 60 to 70% of the bitumen in place at a viscosity of about 100 cP. Others have reported modeling for electromagnetic heating of heavy oil at a frequency of 2.45 GHz, which is equivalent to that used in a domestic microwave oven. Still others have preformed field tests at frequencies of about 13.6 MHz. However, no modeling or experimental work using frequencies in the megahertz range, and relying on the presence of underground water to act as the energy absorber has been reported.